High conformance enhanced oil recovery process

ABSTRACT

The conformance of an enhanced oil recovery process, including water flood, surfactant or other chemicalized water flood process, in a formation containing at least two zones of varying permeability, the permeability of one zone being at least 50 percent greater than the permeability of the other zone, is improved by flooding until the higher permeability zone has been depleted, after which a fluid is injected into the high permeability zone, said fluid having relatively low viscosity at the time of injection and containing a mixture of surfactants or surface active agents which promote the formation of a coarse emulsion in the flow channels of the formation which reduces the permeability of the high permeability zone. Since the viscosity of the fluid injected into the previously flooded, high permeability zone is no greater than water, it is injected easily into the zone and moves through substantially the same flow channels as water would move in the formation. After the permeability of the first zone has been reduced substantially, water flooding may then be accomplished in the second zone which was originally not invaded by the injected water since its permeability was substantially less than the permeability of the first zone.

FIELD OF THE INVENTION

This invention concerns a process for use in subterranean petroleumformations containing two or more zones which differ from one another inpermeability such that water flooding or other enhanced oil recoveryprocesses cannot effectively deplete both zones, resulting in poorvertical conformance. More specifically, the process involves injectinga fluid into the more permeable zone, after it has been depleted bywater flooding or other supplemental oil recovery process, which fluidhas relatively low viscosity at the time of injection but forms a highviscosity, coarse emulsion with the residual hydrocarbon in the depletedzone to reduce the permeability of that zone to subsequently injectedfluids.

BACKGROUND OF THE INVENTION

It is well recognized by persons skilled in the art of petroleumrecovery that only a small fraction of the petroleum originally presentin a formation can be recovered by primary production, e.g., by allowingthe oil to flow to the surface of the earth as a consequence ofnaturally occuring energy forces, or by so called secondary recoveryprocesses which comprise injecting water into the formation by one ormore wells to displace petroleum through the formation toward one ormore spaced apart production wells and then to the surface of the earth.Although water flooding is an inexpensive supplemental oil recoveryprocess, water does not displace oil effectively even in those portionsof the formation through which it passes, because water and oil areimmiscible and the interfacial tension between water and oil is quitehigh. This too has been recognized by persons skilled in the art of oilrecovery, and many surface active agents or surfactants have beenproposed for addition to the flood water, which materials reduce theinterfacial tension between the injected aqueous fluid and the formationpetroleum thereby increasing the microscopic displacement efficiency ofthe injected aqueous fluid. Surfactants which have been disclosed in theprior art for such purposes include alkyl sulfonates, alkylarylsulfonates, petroleum sulfonates, alkyl or alkylarylpolyalkoxy sulfates,alkyl- or alkylarylpolyalkoxyalkyl sulfonates, and nonionic surfactantssuch as polyethoxylated aliphatic alcohols or alkanols, andpolyethoxylated alkyl phenols.

Even if the surface tension between the injected aqueous fluid and thepetroleum present in the subterranean reservoir can be reduced byincorporating surface active agents into the injected fluid, the totaloil recovery efficiency of the process is frequently poor because manysubterranean petroleum-containing reservoirs are comprised of aplurality of layers of widely differing permeabilities. When a fluid isinjected into such a heterogeneous reservoir, the fluid passes primarilythrough the most permeable zones and little or none of the fluid passesthrough the lower permeability zones. If the ratio of permeabilities ofthe zones is as high as 2:1, essentially all of the injected fluidpasses through the more permeable zone to the total exclusion of theless permeable zone. Furthermore, the situation described immediatelyabove causing poor vertical conformance of the injected fluid in aheterogeneous reservoir is aggravated by application of the supplementaloil recovery process itself. If water is injected into a heterogeneousmulti-layered petroleum reservoir, water passes principally through themost permeable zone and displaces petroleum therefrom, and as aconsequence further increases the permeability of that zone.Accordingly, the difference between the permeability of the mostpermeable zone and the lesser permeable zone or zones is increased as aconsequence of applying a fluid displacement oil recovery processthereto, including water flooding, surfactant flooding, etc.

The above described problem of poor vertical conformance in waterflooding operations has also been recognized by persons skilled in theart, and numerous processes have been described in the prior art fortreating the formation to correct the problems resulting from injectingan oil-displacing fluid into a formation having two or more zones ofsignificantly different permeabilities. Many of the these processesinvolve the use of hydrophilic polymers including partially hydrolyzedpolyacrylamide, copolymers of acrylamide and acrylic acid or watersoluble acrylates, polysaccharides, etc. Unfortunately, the fluidsemploying these hydrophilic polymers are substantially more viscous thanwater at the time of injection, and so injection into the zones isdifficult and there is little assurance that they will invade the samezones as would water or another aqueous fluid having about the sameviscosity as water. Accordingly, the effectiveness of theabove-described processes has been restricted to reducing thepermeability of only the most permeable flow channels in a zone, and isfurthermore usually restricted only to the near wellbore zone of theformation, e.g. that portion of the most permeable zone in a formationimmediately adjacent to the injection well, because of the difficulty ofinjecting viscous fluids through great portions of the formation.

In view of the foregoing discussion of the problems associated with poorvertical conformance in heterogeneous formations, it can be appreciatedthat there is a substantial need for a method of treating suchformations to reduce the permeability of the very high permeabilityzones to force subsequently injected oil displacing fluids to pass intothose zones which were originally of lower permeability, and so were notinvaded by the first injected fluids.

DESCRIPTION OF THE PRIOR ART

Numerous references suggest the formation of viscous emulsions on thesurface, and injecting the emulsion into a subterranean formation forthe purpose of decreasing the permeability of a zone which issubstantially more permeable than other zones. These include U.S. Pat.No. 3,149,669; U.S. Pat. No. Re. 27,198 (original patent U.S. Pat. No.3,44,636); U.S. Pat. No. 3,502,146 (1970); and U.S. Pat. No. 3,866,680(1975). U.S. Pat. Nos. 3,827,497 and 3,890,239 describe surfactantwaterflooding processes using a mixture of an organic sulfonate and asulfonated oxyalkylated alcohol.

SUMMARY OF THE INVENTION

We have discovered a process applicable to a subterranean ranean,petroleum-containing formations containing two or more zones, at leastone of which has a permeability at least 50 percent greater than theother zone, which will permit more effective water flooding orsurfactant flooding in both zones. The process involves first injectingwater or other aqueous displacing fluid into the formation to passthrough the more permeable zone, displacing petroleum therefrom, untilthe ratio of injected fluid to formation petroleum of fluids beingrecovered from the formation reaches a predetermined or economicallyunsuitable level. This further increases the ratio of the permeabilityof the most permeable zone to the permeability of the lesser permeablezone or zones. Thereafter an aqueous fluid is injected into theformation, which fluid will pass substantially exclusively into andthrough the most permeable, previously water flooded zone, which fluidhas a viscosity not substantially greater than the viscosity of water,said fluid containing a surfactant mixture which readily emulsifies theresidual oil present in the previously water flooded zone. Thesurfactants present in the injected treating fluid must form a stableemulsion with the formation petroleum at the formation temperature andat a salinity about equal to the salinity of the aqueous fluid presentin the previously flooded, high permeability zone, and should also berelatively stable with changes in salinity since there will normally bevariations in water salinity from one point in the subterraneanformation to another. The emulsion formed should also be stable withtime and changes in salinity at the temperature of the formation, inorder to maintain the desired reduction of permeability within thetreated zone. The surfactants employed in the process of my inventioncomprises at least three components, one of which is an organicsulfonate primary anionic surfactant such as a C₈ to C₂₀ alkyl oralkylaryl sulfonate, or a petroleum sulfonate which is at leastpartially water soluble. The organic sulfonate is solubilized by a dualsolubilizing co-surfactant system comprising (1) analkylpolyalkoxyalkylene sulfonate such as an alkylpolyethoxyethylene,(or propylene, or hydroxypropylene) sulfonate, or analkylarylpolyalkoxyalkylene sulfonate, such as an alkylbenzene, (oralkyl toluene or xylene) polyethoxyethylene, (or propylene or butylene)sulfonate, and (2) a dialkylbenzenepolyalkoxyalkylene sulfonate. Thesurfactant mixture may also contain a nonionic surfactant, specificallyan ethoxylated aliphatic or ethoxylated alkylaryl compound such as anethoxylated aliphatic alcohol or alkanol, or an ethoxylated alkylphenol.This process is applicable to formations containing water whose salinityis from 5,000 to 200,000 parts per million total dissolved solids.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1a illustrates a subterranean oil formation containing three zonesof different permeabilities, illustrating the interface between aninjected fluid and the petroleum in each zone at a time near theeconomic end of a water flood process.

FIG. 1b illustrates the same subterranean formation, after it has beensubject to the treatment of the process of this invention, and thensubjected to additional water flood.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

Briefly, the process of our invention comprises a method of treating asubterranean formation containing at least two zones whosepermeabilities are sufficiently different from one another that a fluidinjected into a well in communication with both zones will passprimarily through the more permeable zone. Ordinarily, for example, ifthe permeability of one zone to the flow of the injected fluid is atleast 50 percent greater than and especially if it is 100 percentgreater than the permeability of the other zone, fluid injected intowells in fluid communication with both zones will pass almostexclusively into the more permeable zone. For example, in a water floodapplied to such a formation, water will pass into the more permeablezone exclusively and will displace petroleum towards the productionwell, with substantially no oil displacement occuring in the lesserpermeable zone. After oil has been displaced through the more permeablezone and oil recovery has proceeded to the point at which waterbreakthrough has occurred at the production well, continued injection ofwater into the well in communication with both zones will accomplishsubstantially no additional oil recovery even though the oil saturationin the lesser permeable zone may be substantially the same as it wasbefore commencing water flood or other supplemental oil recoveryoperations. Moreover, injecting a surfactant fluid which achieves lowinterfacial tension, but which produces no emulsion will have similarresults, to water injection; namely, the surfactant fluid passes throughthe watered out, high permeability zone, bypassing the higher oilsaturation, lower permeability zone.

Attempts to treat a formation such as that described above by techniquestaught in the prior art have been only partially successful for avariety of reasons. Injecting a viscous fluid, which may be either anemulsion formed on the surface for the purpose of plugging the morepermeable zone or an aqueous solution of a hydrophilic polymer such aspolyacrylamide, partially hydrolyzed polyacrylamide, copolymers ofacrylamide and acrylates, polysaccharides, etc., are generally notentirely satisfactory because the more viscous fluid only invades thelargest flow channels of the formation, and so does not invade all ofthe flow channels which would be invaded by a fluid whose viscosity waslower, e.g. more nearly equal to the viscosity of water. Furthermore,emulsions formed by, for example, adding caustic and water to crude oilare not particularly stable with respect of time and are also not stablewith respect to changes in the salinity of fluid with which they maycontact. Thus an emulsion which effectively plugs the larger flowchannels of a high permeability zone, including one which has previouslybeen water flooded, may be broken later either as a consequence of thepassage of time, or as the emulsion contacts pockets of water havinggreater or lesser salinity, such as are frequently found in mostsubterranean reservoirs. Moreover, there are problems associated withadsorption of hydrophilic polymers, and furthermore many of thehydrophilic polymers are not sufficiently temperature stable to allowthem to be used in even moderately higher temperature formations.

The fluid injected into the formation according to the process of ourinvention will ordinarily be an aqueous fluid, e.g. a solutioncontaining at least three surfactants, or surface-active agents, whichare carefully chosen individually and their relative proportionsselected on the basis of displaying optimum emulsificationcharacteristics. Surfactants which are effective for this purpose, e.g.for forming gross macro-emulsions capable of plugging the flow channelsof the formation, are not suitable for low surface tension floodingoperations, and will not produce optimum oil displacement in a formationif utilized in a surfactant water flooding process. The differencebetween an emulsifying surfactant for use in our process and onesuitable for use in surfactant waterflooding is in the balance betweenwater soluble and oil soluble groups, and may only require a slightchange in the number of ethoxy groups in the ethoxy sulfonates. Thereason the surfactants suitable for use in the process of this inventionare ineffective for waterflooding operations is believed to beassociated with the fact that when an emulsion is formed, essentiallyall of the surface active agents which participate in the emulsificationreaction, are concentrated at the interface between the discontinuousand continuous emulsion phases, and so little of the surfactants remainin the aqueous solution, and so cannot reduce the interfacial tensionbetween formation petroleum and the aqueous fluid present in the flowchannels as is necessary to achieve efficient low surface tensiondisplacement of petroleum.

It is necessary that the surfactants utilized in the process of ourinvention be stable and effective for emulsification in an aqueous fluidhaving a salinity about equal to the average salinity of the aqueousfluid present in the flow channel of the high permeability zone, e.g.the zone into which the treating fluid is to be injected. Preferably,the surfactant should be identified by tests utilizing actual fluidsfrom the formation, including brine and formation petroleum, sinceparticular characteristics of any of these fluids will affect theefficiency of the surfactant for emulsification of formation petroleumand injected aqueous fluid.

The aqueous emulsifying treating fluid injected into the highpermeability zone in practicing the process of our invention contains atleast the following three surfactants. (1) An organic sulfonate, whichmay be a synthetic sulfonate having the following formula:

    R--SO.sub.3 M

wherein R is an aliphatic group, including alkyl, linear or branched,having from C₆ to C₂₀ and preferably from C₉ to C₁₈ carbon atoms, or analkylaryl group such as a benzene, toluene or xylene having attachedthereto one or more alkyl groups, linear or branched, each having fromC₆ to C₂₀ and preferably from C₉ to C₁₈ carbon atoms, and M is amonovalent cation such as ammonium, sodium, potassium or lithium.

The organic sulfonate may also be an ammonium, sodium, potassium, orlithium salt of petroleum sulfonate. The preferred petroleum sulfonatecomprises a mixture of molecular species with equivalent weights fromabout 250 to 550 and a median equivalent weight in the range of from 350to 420. (2) A sulfonated and ethoxylated surfactant having the followingformula:

    R.sub.a (OR.sub.a ').sub.na R.sub.a "SO.sub.3 M.sub.a

wherein R_(a) is an aliphatic group, preferably an alkyl, linear orbranched, having from 9 to 25 and preferably from 12 to 18 carbon atoms,or an alkylaryl group such as benzene, toluene or xylene having attachedthereto one alkyl group, linear or branched, having from 9 to 15 andpreferably from 10 to 13 carbon atoms; R_(a) ' is ethylene or a mixtureof ethylene and higher molecular weight alkylene with relatively moreethylene than higher molecular weight alkylene; na is a number includingfractional numbers, from 2 to 10 and preferably from 3 to 7; R_(a) " isethylene, propylene, hydroxy propylene, or butylene; and M_(a) is amonovalent cation such as sodium, potassium, lithium or ammonium.

(3) A sulfonated and ethoxylated dialkylaryl surfactant having thefollowing formula:

    R.sub.b --(OR.sub.b ').sub.nb --R.sub.b "SO.sub.3 M.sub.b

wherein R_(b) is a dialkylaryl group such as benzene or toluene havingattached thereto at least two alkyl groups, linear or branched, eachhaving from 1 to 18 and preferably from 3 to 12 carbon atoms; R_(b) ' isethylene or a mixture of ethylene and higher molecular weight alkylenewith relatively more ethylene than higher molecular weight alkylene, nbis a number including fractional numbers, from 2 to 10 and preferablyfrom 3 to 7; R_(b) " is ethylene, propylene, hydroxy propylene, orbutylene; and M_(b) is a monovalent cation such as sodium, potassium,lithium or ammonium.

The above-identified three surfactants may be substantially the onlysurfactant present in the treating fluid injected into the highpermeability zone. In a slightly different embodiment, the followingnonionic surfactant may also be used in combination with the organicsulfonate, the alkyl or alkylarylpolyalkoxyalkyl sulfonate and thedialkylarylpolyalkoxyalkyl sulfonate surfactants:

    R.sub.c (OR.sub.c ').sub.nc OH

wherein R_(c) is a aliphatic, such as branched or linear alkyl,containing from 9 to 25 carbon atoms and preferably from 12 to 18 carbonatoms, or an alkylaryl group such as benzene, toluene or xylene havingattached thereto at least one alkyl group, linear or branched,containing from 9 to 15 and preferably from 10 to 13 carbon atoms in thealkyl chain; R_(c) ' is ethylene or a mixture of ethylene and higheralkylene such as propylene with relatively more ethylene than higheralkylene; and nc is a number, either whole or fractional, from 1 to 10and preferably from 2 to 6.

The concentration of the organic sulfonate will be from 0.2 to 5.0 andpreferably from 0.75 to 3.00 percent by weight.

The concentration of the alkyl or alkylarylpolyalkoxyalkylene sulfonatesurfactant will ordinarily be in the range of from about 0.01 to about10 and preferably from about 0.5 to about 4.0 percent by weight. Theconcentration of dialkylarylpolyalkoxyalkylene sulfonate is in the rangeof from 0.1 to 5.0 and preferably from 0.4 to 2.0 percent by weight. Theconcentration of the nonionic surfactant, if utilized in the treatingfluid in the process of our invention, will ordinarily be from about 0.1to about 5.0 and preferably from about 0.4 to about 2.0 percent byweight. The ratio of organic sulfonate surfactant to the alkyl oralkylarylpolyalkoxyalkyl sulfonate and dialkylarylpolyalkoxyalkylsulfonate will ordinarily be from about 0.5 to about 5.0, depending onthe salinity of the fluid in which it is formulated, which in turn isusually about equal to the salinity of the fluid present in thesubterranean formation.

The volume of treating fluid to be injected into the formation whenapplying the process of our invention is ordinarily from about 1.0 toabout 100 and preferably from 10 to 50 pore volume percent, based on thepore volume of the high permeability zone or zones to be contacted bythe treating fluid. It is important to note that the pore volume onwhich these numbers are based relate to the pore volume of the highpermeability zone to be treated, not the pore volume of the wholeformation.

The process of our invention is suitable for use in formationscontaining water of salinity from 5,000 to 150,000 ppm total dissolvedsolids, and whose temperature is from 65° F. (18° C.) to 250° F. (121°C.).

The procedural steps involved in applying the process of our inventionto a subterranean formation are best understood by referring to theattached drawing, to which the following description applies.

A subterranean, petroleum-containing formation is located at depth ofabout 6200 feet, and it is determined that the total thickness of theformation is 35 feet. The average salinity of the water present in theformation is 85,000 parts per million total dissolved solids including20,000 parts per million divalent ions, e.g. calcium and magnesium. Theformation is not homogeneous in terms of permeability, however; rather,the formation is made up of three separate zones or layers. The initialoil saturation in all three layers is approximately 30 percent. Oilsaturation in the drawing is designated S_(o). Zone 1, the top layer inthe formation, has a permeability of about 6 md (millidarcies) and isapproximately 10 feet thick. Zone 2, the middle zone of the formation,has a permeability of about 46 md and is about 15 feet thick. Zone 3,which occupies the lower portion of the formation, is approximately 10feet thick and has an average permeability of about 15 md.

Water is injected into injection well 5 which is in fluid communicationwith the full vertical thickness of the formation, i.e., all three zonesof the formation. Since the permeability of zone 2 is substantiallygreater than either zone 1 or zone 3, water flows much more readily intozone 2, and all of the oil production obtained as a consequence of waterinjection is in fact derived from zone 2. It should be noted that thisis not necessarily apparent to operators on the surface of the earth,however. Water injection continues and an interface is formed in eachzone between the injected water flood and an oil bank that is formed asa consequence of the water flood, the three interfaces being designatedas 6 in zone 1 and 7 in zone 2 and 8 in zone 3. At a time just beforewater breakthrough at the production well 4, the position of interfacialzones 6, 7 and 8 is shown in FIG. 1a. It can be seen that waterbreakthrough is about to occur at production well 4 from zone 2. Oncewater breakthrough occurs, further injection of water into well 5 willnot recover any significant amount of additional oil from any of thethree zones. All of the water injected after breakthrough of water atproduction well 4 will pass into and through zone 2, and essentially noadditional water will pass into zones 1 and 3. Thus interfacial zone 6and 8 will remain approximately where they are shown in FIG. 1a afterbreakthrough of water into the production well at zone 2, no matter howmuch additional water is injected into the injection well and flowedthrough the reservoir. At this time oil production drops off rapidly andthe amount of water being produced increases rapidly until further waterinjection and oil production are no longer economically feasible.

The water that has been utilized for water flooding is itself from thesame formation, and so the salinity of the water being injected into theformation and the salinity of water naturally present in the formationis about the same, and it is determined that in this example thesalinity of this water is approximately 85,000 parts per million totaldissolved solids including 20,000 parts per million divalent ions,principally calcium and magnesium. The formation temperature is 109° F.(43° C.). It is desired to formulate a treating fluid suitable for usein this salinity environments, which forms emulsions stable at thistemperature, and the surfactant is chosen by a series of laboratoryexperiments employing actual samples of field water and petroleum fromthe formation into which the treating fluid is to be injected. After aseries of laboratory tests, essentially similar to those to be describedlater hereinafter below, it is determined that a preferred emulsifyingfluid for use in reducing the permeability of zone 2 contains (1) 1.3percent by weight of a sodium petroleum sulfonate having a medianequivalent weight of 375 and containing molecular species havingequivalent weights evenly distributed over the range of 300-550; (2)0.75 percent by weight of a sodium nonylbenzenepolyethoxyethylenesulfonate containing an average of 5 ethoxy groups per molecule; and (3)0.75 percent by weight of a sodium dinonylbenzenepolyethoxypropylenesulfonate containing 3.0 moles ethylene oxide per mole of surfactant.

Since the wells are 150 feet apart, and the formation to be treated isprincipally zone 2, which is 15 feet thick and its porosity is 30percent, and since it is determined that the swept area in a simpletwo-well pattern such as this is 11,200 square feet, the volume offormation (30% porosity) to be treated is (11,200)(15)(0.30)=50,400 cu.ft.

A 20 percent pore volume or 10,080 cu. ft. slug is chosen for use intreating the above identified zone. Accordingly, the volume of thesolution necessary to treat zone 2 in this example is approximately 2133cubic meters or 75,398 gallons.

The above described emulsifying fluid is injected into injection well 5.Because the permeability of zone 2 is substantially greater than thepermeability of zones 1 and 3 at that time, the difference beingsubstantially greater than existed at the time water flooding wasinitiated, it is not necessary to isolate zone 2 from the other zonesfor the purpose of selectively injecting the fluid into zone 2.Substantially all of the fluid injected into well 5, which is in fluidcommunication with all three zones of the formation, will pass into zone2. Injection of the treating fluid into zone 2, which causes an emulsionto form in zone 2, reducing the permeability of the zone andadditionally recovering some additional oil therefrom, reduces the oilsaturation in zone 2 to only 4 percent. Water injection into theformation is then resumed. Since the permeability of zone 2 has beendecreased substantially by the foregoing treatment, water injected intowell 5 will now flow principally into zones 1 and 3, and so willcontinue pushing the interface between the injected water and theformation petroleum toward the production well. If water from zone 3breaks through at producing well 4 before it does from zone 1, it may benecessary to treat zone 3 with essentially the same process as was usedto treat zone 2 as described above. If this is accomplished, the waterinjection may again be resumed, with essentially all of the waterpassing into zone 1. Water injection is then continued until water againbreaks through at well 4, signifying that substantially all of theformation has been swept by water flooding.

After completion of the above described multi-step water flood withintermittent treatment to alleviate the adverse permeabilitydistribution problem, the formation may thereafter be subjected toadditional supplemental oil recovery processes such as, for example,surfactant flooding, since the permeability of the formation has nowbeen made more homogeneous and there still remains a substantial amountof petroleum in zones 1 and 3 sufficient to justify the injection of aneffective, low surface tension oil displacing fluid into zones 1 and 2.Alternatively, surfactant waterflooding may be applied immediately afterthe permeability adjusting steps, omitting the waterflooding step, usinga surfactant tailored to achieve low interfacial tension displacement ofpetroleum. It must be recognized that the surfactants employed in thislatter fluid will be different from the emulsifying fluid used in theformer process treating the formation to effect a decrease in thepermeability differences, according to the process of our inventiondescribed herein, and the fluids are not interchangeable, since asurfactant which effects low interfacial, tension and so exhibitsoptimum low tension oil displacement performance is generallyineffective for forming an emulsion for use in our process.

The difference between an optimum surfactant for emulsification and onewhich is optimum of low surface tension oil displacement is achieved bya slight shift in the balance between the oil soluble group (e.g. R_(a)or R_(b) in the above formulas, and the number of ethoxy groups presentin either or both of the ethoxylated and sulfonated surfactants.

A series of emulsification test was performed to illustrate how slightchanges in the molecular structure of a surfactant cause significantchanges in the emulsification effectiveness of the surfactants. Thesetests comprising mixing 5 l cc. of oil and 30 cc. of a 1 percentsurfactant solution prepared in brine whose salinity was 85,000 partsper million total dissolved solids, heating to 109° F. (43° C.) andshaking periodically over an eight hour period. The samples were thenallowed to equilibrate for several days, and the volume of emulsion andtotal volume of fluid (including emulsion and separate oil and waterphases) were observed. The data in Table I below show the ratio of thevolume of emulsion formed to the total fluid volume. It can be seen thata change of only ±0.2 in the number of moles of ethylene oxide per moleof surfactant causes a significant change in the effectiveness of thesurfactant for producing an emulsion.

                  TABLE I                                                         ______________________________________                                                 Average number of                                                                              Ratio of Emulsion                                            moles of EO per mole                                                                           Volume to Total                                     Run      surfactant (1)   Fluid Volume                                        ______________________________________                                        A        2.6              0.02                                                B        2.8              0.39                                                C        3.0              0.02                                                D        3.2              0.00                                                E        3.4              0.00                                                ______________________________________                                         (1) 1% dodecylbenzenepolyethoxyhydroxypropylene sulfonate.               

For the purpose of further illustrating the types of fluids suitable foruse in the process of our invention, and illustrating the resultsobtainable from application thereof, a series of laboratory experimentswere performed. Laboratory equipment was especially constructed forthese tests, and comprised essentially two separate formation earth coresamples encased in holders and arranged for flooding, with the two coresbeing placed in parallel to simulate the situation similar to thatdescribed above, in which an injection well is in communication with twoearth strata of substantially different permeabilities. Fluids injectedinto the apparatus will pass predominantly through the highestpermeability core to the exclusion of the other core. In all of theexperiments described below, the cores were separately water flooded toan irreducable oil saturation prior to being connected in parallel forthe purpose of studying the effect of the adverse permeabilitydistribution-correcting treatment of my invention.

In run F, two packs of crushed formation core material were formulatedand cleanes. The packs were 3.49 cm in diameter and 20 cm in length andhad a total pore volume of 56 cubic centimeters. The porosity of pack 1was 29 percent and the permeability was 208 millidarcy. The residual oilsaturation after water flooding was 27 percent. Pack 2 utilized in Run Fhad a pore volume of 44 cubic centimeters and a porosity of 23 percent,but a much lower permeability, only 14 millidarcy. The residual oilsaturation of Pack 1 after water flooding was 32 percent. After thepacks were flooded to irreducable water saturation and mounted inparallel, water injection into the cores at a flow rate of 0.9 cc perminute resulted in a receptivity ratio (the ratio of the volume of fluidinjected into Pack 1 divided by the volume of fluid injected into Pack 2during the same period, when the cores are connected in parallel) ofapproximately 11.7. During the treatment with 3.0% sodium dinonylbenzene(4.8) polyalkoxyethylene sulfonate solution the receptivity ratiodeclined to 6.4 and levelled off at 5.3 during the subsequently appliedwater flood operation. A quantity of petroleum sulfonate solution wasthen injected, and during the surfactant flood portion of the test, thereceptivity declined still further to 3.1. A polymer mobility controlbuffer was then injected into the system, and the receptivity ratioincreased to 1.3 after 0.5 pore volumes of the polymer solution had beeninjected, and then rose to 2.2 after 4.0 pore volumes of polymer hadbeen injected. It is believed that the increase in receptivity ratioresulting from the fact that the polymer was dissolved in fresh water,which broke some of the emulsion formed in the course of the treatementprocedure described above. Nevertheless, Run F clearly illustrates howtreatment of two cores in a parallel arrangement, which cores havewidely different permeabilities, can reduce the permeability deviationbetween the two cores and improve the receptivity ratio.

Run G was performed using packs of crushed limestone to verify that insitu emulsification was the mechanism responsible for the improvement inreceptivity noted in experiment F above. Pack 3 was saturated with crudeoil and pack 4 was not. Pack 3 was water flooded to an irreducable oilsaturation prior to the treatment. Both packs were treated with 13 porevolume percent of a 30 kilogram/meter³ solution ofdinonylphenolpolyethoxyethyl sulfonate (3.8 ethoxy groups per moleculeaverage) and finally flooded with field brine. In this experiment, thepacks were not flooded in parallel as was the case in Run F above butrather were independently flooded after treatment with the emulsifyingfluid. The pressure differential across the packs was determined duringthe course of the treatment and subsequent water flood as an indicationof increasing resistance to fluid flow through the packs. Pack 3, whichwas originally saturated with oil, water flooded and then treated,experienced a four-fold increase in the pressure required to flood withwater in a constant rate flood whereas pack 4, which containedessentially no oil prior to the treatment, experienced less than a 50percent increase in differential pressure during the course ofapproximately 3 pore volumes of water flood. Run G clearly illustratesthat oil must be present in the treated formation for theinjectivity-reducing emulsification phenomena to be achieved, which isnecessary for the treatment described herein to accomplish the desiredobjective of reducing the permeability of the high permeability zone.

Run H was similar to Run F, except the treating solution contained 13.6kg/m³ dodecylbenzene (3.0) polyethoxyethylene sulfonate with 7.6 kg/m³3.0 mole ethylene oxide adduct of dodecyl phenol. Pack 5 had 96millidarcy permeability and Pack 6 had 20 millidarcy permeability. Afterthe packs were each flooded to irreducable water saturation and mountedin parallel, water injection into the cores at a flow rate of 1.0 cm³per minute in A receptivity ratio (Pack 5/Pack 6) of 4.6. During thetreatment procedure, the receptivity ratio decline to 2.8 and levelledoff at 1.0 during the subsequently applied water flood operation. Areceptivity ratio of 1 was maintained during injection of petroleumsulfonate solution and the ratio fluctuated between 1.6 and 0.6 during apolymer solution injection. Experiment H clearly illustrates that thesulfonate-nonionic mixture can be used to reduce the permeabilitydeviation between two packs.

Experiment I was conducted to evaluate the specific preferred embodimentof this invention, employing petroleum sulfonate and dual sulfonated andethoxylated solubizing cosurfactants. Two fluids were employed. Thefirst fluid contained the following component:

3.6 percent sodium dinonylbenzene (4.8) polyethoxyethylene sulfonate.

The second fluid contained the following 3 components:

(1) 1.5% sodium nonylbenzene (6.0) polyethoxyethylene sulfonate,

(2) 1.1% Witco TRS 18® petroleum sulfonate,

(3) 2.5% Witco TRS 40® petroleum sulfonate.

No isolation slug was used between the two fluids to enhance mixing ofthese fluids in the cores. The salinity of each solution was 90,000parts per million total dissolved solids and total hardness of 25,000ppm as calcium carbonate. It can be seen from the data in Table II belowthat a severe injection ratio of 8.7 was corrected to very nearly unityby our process.

                                      TABLE II                                    __________________________________________________________________________                                         Receptivity                                                                           Ratios                              Core or                                                                             Initial Permeability                                                                      Volume of Material                                                                            Prior   After ΔP After                                                                Treatment                  Run                                                                              Pack  to Water    Treating Fluid                                                                          Used  To Treatment                                                                          Treatment                                                                           ΔP Before                                                               Treatment                  __________________________________________________________________________       1     209         0.15.sup. 2 ; 0.27.sup.4                                    2     15          0.03.sup.2 ; 0.11.sup.4                                     3     75          0.13            --      --    4.0                        G                              .sup.2                                            4     65          0.17            --      --    1.4                           5     96                                                                   H                              .sup.3                                                                              4.6     1.0   --                            6     20                                                                      7     133         0.15.sup.2 ; 0.22.sup.4                                  I                                    8.7     0.8-1.4                             8     10          0.04.sup.2 ; 0.17.sup.4                                  __________________________________________________________________________     .sup.1 Reduced to 2.4 on injecting petroleum sulfonate oil displacing         fluid                                                                         .sup.2 Dinonylphenol (3.8) polyethoxyethyl sulfonate                          .sup.3 Dodecylphenol (3.0) polyethoxyethyl sulfonate + dodecylphenol (3.0     polyethoxylate                                                                .sup.4 Petroleum sulfonate plus dinonylbenzene (4.8) polyethoxyethylene       sulfonate plus nonylbenzene (6.0) polyethoxyethylene sulfonate           

While portions of the above description of the preferred embodimentsdisclose mixing all of the surfactants in one fluid and injecting theminto the formation, two or more fluids each containing one or more ofthe essential surfactants may be injected sequentially to achieve mixingin the formation. In certain applications, there is an advantage toinjecting the materials sequentially in that emulsification is delayedsomewhat and greater in depth treatment is achieved.

Thus we have disclosed and demonstrated how it is possible to treat aformation containing two or more strata of substantially differentpermeabilities so as to reduce the permeability of the more permeablestrata, by injecting one or more emulsifying fluids thereinto which forma gross macro-emulsion with residual oil remaining in the flow channelsof the flooded portion of a formation after water flooding, therebyreducing the permeability difference between the strata, after whichwater or other oil displacing fluids may be injected into the formationwith substantially improved vertical conformance over that which wouldbe obtained without the permeability adjusting treatment of ourinvention.

While our invention has been described in terms of a number ofillustrative embodiments, it is clearly not so limited since manyvariations thereof will be apparent to persons skilled in the art of oilrecovery without departing from the true spirit and scope of ourinvention. It is our desire and intention that our invention be limitedonly by those limitations and restrictions appearing in the claimsappended immediately hereinafter below.

We claim:
 1. A method of recovering petroleum from a subterranean,petroleum-containing formation, said formation containing water whosesalinity is from 5,000 to 220,000 parts per million total dissolvedsolids, said formation containing at least two distinctpertoleum-containing strata, the permeability of at least one of saidstrata being at least 50 percent greater than the permeability of theother stratum, said formation being penetrated by at least one injectionwell and by at least one production well, both wells being in fluidcommunication with substantially all of said formation, comprising(a)injecting a first aqueous oil-displacing fluid into the formation viathe injection well, said fluid passing through at least one of the morepermeable strata of said formation and displacing oil therein toward theproduction well, from which it is recovered to the surface of the earth;(b) after said first aqueous oil displacing fluid has passed through atleast one of said more permeable strata to the production well,discontinuing injecting said fluid and injecting into said stratum atleast one aqueous fluid containing an emulsifying surfactant mixturecomprising(1) from 0.2 to 5 percent by weight of an organic sulfonatecomprising an alkyl or alkylaryl sulfonate having the following formula:

    R--SO.sub.3 M

wherein R is an alkyl group containing from 6 to 20 carbon atoms, or analkylaryl group selected from the group consisting of benzene, tolueneor xylene having attached thereto at least one alkyl containing from 6to 20 carbon atoms, and M is ammonium, sodium, potassium, or lithium, ora sodium, potassium, lithium, or ammonium salt of petroleum sulfonatewhich is at least partially water soluble and has a median equivalentweight in the range of 350 to 420; (2) from 0.01 to 5.0 percent byweight of a dialkylarylpolyalkoxyalkylene sulfonate having the followingformula:

    R.sub.a (OR.sub.a ').sub.na R.sub.a "SO.sub.3 M.sub.a

wherein R_(a) is a dialkylaryl group selected from the group consistingof benzene and toluene having attached thereto at least two alkylgroups, each having from 3 to 14 carbon atoms, R_(a) ' is ethylene or amixture of ethylene and higher alkylene with relatively more ethylenethan higher alkylene, na is a number from 2 to 10, R_(a) " is ethylene,propylene, hydroxypropylene or butylene, and M_(a) is ammonium, sodium,potassium or lithium; and (3) from about 0.01 to about 10.0 percent byweight of an alkylpolyalkoxyalkylene sulfonate oralkylarylpolyalkoxyalkylene sulfonate having the following formula:

    R.sub.b --(OR.sub.b ').sub.nb --R.sub.b "SO.sub.3 M.sub.b

wherein R_(b) is an alkyl group having from 9 to 25 carbon atoms or analkylaryl group selected from the group consisting of benzene, tolueneor xylene having attached thereto one alkyl group, having from 9 to 15carbon atoms; R_(b) ' is ethylene or a mixture of ethylene and highermolecular weight alkylene with relatively more ethylene than highermolecular weight alkylene; nb is a number from 2 to 10, R_(b) " isethylene, propylene, hydroxy propylene, or butylene and M_(b) is amonovalent cation selected from the group consisting of sodium,potassium lithium and ammonium, said emulsifying surfactant mixtureforming a macro-emulsion in the flow channels of the most permeablestrata of the formation, thereby reducing the permeability of the stratainvaded by the emulsifying fluid; and (c) thereafter injecting a secondaqueous oil displacing fluid into the formation, said oil displacingfluid invading at least one stratum not invaded by the oil displacingfluid of step (a) above, displacing petroleum therein toward theproduction well where it is recovered to the surface of the earth.
 2. Amethod as recited in claim 1 wherein the first oil displacing fluid iswater.
 3. A method as recited in claim 1 wherein the second oildisplacing fluid is water.
 4. A method as recited in claim 1 wherein theemulsifying fluid also contains a nonionic surfactant having thefollowing formula:

    R.sub.c (OR.sub.c ').sub.nc OH

wherein R_(c) is an alkyl group containing from 9 to 25 carbon atoms, oran alkylaryl group selected from the group consisting of benzene,toluene and xylene having attached thereto at least one alkyl containingfrom 9 to 15 carbon atoms, R_(c) ' is ethylene or a mixture of ethyleneand propylene with relatively more ethylene than propylene; and nc is anumber from 2 to
 10. 5. A method as recited in claim 1 wherein R_(b) isan alkyl group containing from 12 to 18 carbon atoms.
 6. A method asrecited in claim 1 wherein R_(b) is alkylaryl group and the number ofcarbon atoms in the alkyl group is from 10 to
 13. 7. A method as recitedin claim 6 wherein R_(b) is alkylbenzene.
 8. A method as recited inclaim 1 wherein R_(a) ' is ethylene.
 9. A method as recited in claim 1wherein R_(b) ' is ethylene.
 10. A method as recited in claim 1 whereinthe value of na is from 2 to
 7. 11. A method as recited in claim 1wherein the value of nb is from 2 to
 7. 12. A method as recited in claim1 wherein R_(a) " is ethylene.
 13. A method as recited in claim 1wherein R_(b) " is ethylene.
 14. A method as recited in claim 1 whereinR_(a) " is propylene.
 15. A method as recited in claim 1 wherein R_(b) "is propylene.
 16. A method as recited in claim 1 wherein R_(a) " ishydroxy propylene.
 17. A method as recited in claim 1 wherein R_(b) " ishydroxy propylene.
 18. A method as recited in claim 1 wherein R_(a) " isbutylene.
 19. A method as recited in claim 1 wherein R_(b) " isbutylene.
 20. A method as recited in claim 4 wherein the ratio of thenonionic surfactant to the sum of the alkylpolyalkoxyalkylene sulfonateor alkylarylpolyalkoxyalkylene and the dialkylarylpolyalkoxyalkylenesulfonate is from about 0.5 to about 5.0.
 21. A method as recited inclaim 1 wherein the volume of emulsifying surfactant-containing fluid isfrom about 1.0 to about 100 pore volume percent based on the pore volumeof the strata to be treated thereby.
 22. A method as recited in claim 21wherein the volume of fluid is from about 10 to about 50 pore volumepercent.
 23. A method as recited in claim 1 wherein said formationcontains at least three strata, each differing in permeability from oneanother, and the steps of injecting said emulsifyingsurfactant-containing fluid and then resuming injecting said aqueousoil-displacing fluid are applied to the formation at least twice.
 24. Amethod as recited in claim 23 wherein the steps of injecting saidemulsifying surfactant-containing fluid and said aqueous oil-displacingfluid are repeated until oil-displacing fluid has swept substantiallyall of the petroleum-containing strata of said formation.
 25. A methodof recovering petroleum from a subterranean, petroleum-containingformation, said formation containing water whose salinity is from 5,000to 220,000 parts per million total dissolved solids, said formationcontaning at least two distinct petroleum-containing strata, thepermeability of at least one of said strata being at least 50 percentgreater than the permeability of the other stratum, and formation beingpenetrated by at least one injection well and by at least one productionwell, both wells being in fluid communication with said formationstrata, comprising(a) injecting a first aqueous fluid comprising anoil-displacing fluid into the formation via the injection well, saidfluid passing through at least one of the more permeable strata of saidformation and displacing oil therein toward the production well, fromwhich it is recovered to the surface of the earth; (b) after said firstaqueous fluid has passed through at least one of said more permeablestratum to the production well, discontinuing injecting said fluid andinjecting into said stratum a second aqueous fluid containing from 0.2to 5.0 percent by weight of an organic sulfonate comprising an alkylsulfonate or alkylaryl sulfonate having the following formula:

    R--SO.sub.3 M

wherein R is an alkyl containing from 6 to 20 carbon atoms, or analkylaryl selected from the group consisting of benzene, toluene orxylene having attached thereto at least one alkyl containing from 6 to20 carbon atoms, and M is ammonium, sodium, potassium, or lithium, or asodium, potassium, lithium, or ammonium salt or petroleum sulfonatewhich is at least partially water soluble and has a median equivalentweight in the range of 350 to 420; (c) injecting a third aqueous fluidcontaining from 0.01 to 5.0 percent by weight of adialkylarylpolyalkoxyalkylene sulfonate having the following formula:

    R.sub.a (OR.sub.a ').sub.na R.sub.a "SO.sub.3 M.sub.a

wherein R_(a) is a dialkylaryl selected from the group consisting ofbenzene and toluene having attached thereto at least two alkyl groupseach having from 3 to 14 carbon atoms, R_(a) ' is ethylene or a mixtureof ethylene and higher alkylene with relatively more ethylene thanhigher alkylene, na is a number from 2 to 10, R_(a) " is ethylene,propylene, hydroxypropylene or butylene, and M_(a) is ammonium, sodium,potassium or lithium; (d) injecting a fourth aqueous fluid containingfrom 0.01 to 10.0 percent by weight of an alkylpolyalkoxyalkylenesulfonate or alkylarylpolyalkoxyalkylene sulfonate having the followingformula:

    R.sub.b --(OR.sub.b ').sub.nb --R.sub.b "SO.sub.3 M.sub.b

wherein R_(b) is an alkyl having from 9 to 25 carbon atoms or analkylaryl selected from the group consisting of benzene, toluene orxylene having attached thereto one alkyl group having from 9 to 15carbon atoms; R_(b) ' is ethylene or a mixture of ethylene and highermolecular weight alkylene with relatively more ethylene than highermolecular weight alkylene; nb is a number from 2 to 10, R_(b) " isethylene, propylene, hydroxy propylene, or butylene and M_(b) is amonovalent cation selected from the group consisting of sodium,potassium lithium and ammonium; (e) said second, third and fourth fluidsbeing injected sequentially to mix in the stratum of the formationinvaded by the first aqueous fluid, forming a macro-emulsion in the flowchannels of said stratum, thereby reducing the permeability of saidstratum invaded by the emulsifying fluid; and (f) thereafter injecting afifth aqueous fluid comprising an aqueous oil displacing fluid into theformation, said oil displacing fluid invading at least one stratum notinvaded by the oil displacing fluid of step (a) above, displacingpetroleum therein toward the production well where it is recovered tothe surface of the earth.